Separator and method  for removing free gas from a well fluid

ABSTRACT

A separator for removing free gas from a fluid extracted from a well, comprising a conventional electric submersible pump system, with a centrifugal gas separator, coupled to a static, gas separator of the gas anchor type, via a an ESP capsule, which has a closed upper end that forms a seal against the casing of the centrifugal gas separator and a lower conical end, with an adapter on the lower end of the capsule, which is connected to the upper end of the static separator. Also disclosed is a method for separating free gas from a fluid extracted from a well Among other advantages, aspects disclosed enable gas to be separated more efficiently and a fluid with a larger amount of liquid and low gas concentration to be sent to the production pump, such that the amount of gas enables the pump system to remain as stable as possible.

FIELD OF THE INVENTION

The present invention relates to a new separator for removing free gas from a fluid extracted from a well. Said separator is characterized in that it comprises a static gas separator on the lower end thereof, commonly used in progressing cavity pump (PCP) systems and mechanical pumping, adapted by means of a capsule to a conventional electric submersible pump system that uses a centrifugal gas separator. The invention herein disclosed enables gas to be further separated in two different stages, with the aim of sending a fluid with a larger amount of liquid and low gas concentration to the pump, so that it can be completely handled in order to keep the pump system as stable as possible.

STATE OF THE ART

One of the biggest drawbacks that an electric submersible pump system can have is being able to operate in oil wells with fluid that has considerable amounts of gas that cannot be removed by means of a conventional design based on a centrifugal gas separator.

This situation leads to losses in the efficiency of the pump, destabilization of the liquid production of the well, fluctuations in the power consumed by the electric submersible motor, inaccuracies in the production tests of the well and other problems, such as the heating of the pump and the inability to obtain the highest possible rate of liquid production of an oil well. Overheating of the motor can lead to progressive deterioration of the material of the inner coiling and accelerated degradation of the physical properties of dielectric oil, tending to reduce the useful life of this equipment.

Another negative effect is the heating of the pump itself, since by handling considerable amounts of gas within the internal parts thereof (impellers and diffusers), a cavitation effect is created that produces overheating of the stages during centrifugal movement at high speeds (normally between 2400 and 3600 revolutions), which is transferred by convection to the casing of the pump, putting the integrity of the guiding motor cable that transmits electrical energy to the motor at risk, since it is in direct physical contact with said casing. Included in this context is the document CA2207770, which relates to a method for improving the processing capacity of the immersion pumps by means of the incorporation of a gas separator. This document set the standard for new devices that incorporate a gas separator to improve the operability of the electric submersible pump systems. Thus, as in the state of the art, there are several documents that refer to gas separators placed before the electric submersible pump, with the aim of reducing the amount of free gas present in the fluid extracted from the well before said fluid enters the pump system.

Moreover, the developed separators already combine multiple stages or multiple cavities. This is the case of the patent U.S. Pat. No. 7,461,692, which discloses a multi-stage gas separator. The device discloses a single unit with multiple separation stages, but it does not suggest that two or more separators can be coupled in series. Another document related to the subject matter is the patent CN202417466U, which discloses a separator with multiple cavities, at least three, each of which acts as an independent separator. In this document, all the separator elements are integrated inside a single sealed unit, said separators are centrifugal and do not include a static separator.

In addition to the aforementioned documents, the application CA2291366 was found which is intended for a gas separator with multiple separation chambers. This device is contained in a single unit and it does not suggest that two or more separators be coupled in series. Regarding this subject matter, the document U.S. Pat. No. 5,902,378 was also found, relating to a gas separator that has a single annular chamber where the separation of the gases from the liquid is carried out. The teachings of these documents do not suggest the possibility of connecting two or more separators in series.

Furthermore, other documents were found relating to gas separators with multiple stages. Among them, the document U.S. Pat. No. 4,241,788, which discloses a gas separator comprising a plurality of retaining cups contained inside a single unit, and the document CA2899903, which relates to an abrasion resistant gas separator. This separator corresponds to a plurality of stages, all contained inside a single unit.

Likewise, it was established that the document CN2450385U refers to a highly efficient, multi-stage gas separator comprising more than two gas separator units with the same structure, which are arranged on the same drive shaft and are connected in series at the bases. According to the figures of this application, the gas separators used in this invention are static, and the bases between the separator of the first stage and the separator of the second stage are joined by means of a threaded connection, while the bases between the separator of the second stage and the separator of the third stage are connected by means of a flange and bolts. According to this application, the separator disclosed in said document increases the efficiency of separating gas-oil more than two-fold, in comparison to a normal electric submersible pump, while the range of application of the efficiency of the electric submersible pump can be extended and the efficiency of said pump can be increased.

Finally, the document U.S. Pat. No. 4,901,413 was found, which discloses a method and an apparatus with multi-stage gas separation. Said apparatus comprises conventional separators connected in series by means of an adaptor that directly joins the separators. Although this document and the prior document disclose separators comprising two or more separators connected in line and an adaptor therebetween, the separators used are static separators, even those that comprise separators connected in series and joined to an electric submersible pump system, as in the case of CN2450385U.

The applicant of the present invention has developed and incorporated centrifugal gas separators that operate in the electric submersible pump system. However, these separators are not 100% efficient at eliminating the total amount of gas present in some extracted well fluids, and therefore, the system continues to be subjected to the adverse effects caused by the gas when found in large amounts.

It especially requires a design and method aimed at using electric submersible pump systems in oil wells with high gas production rates, gas/liquid ratios equal to or greater than 1000 standard cubic feet (28316.8 liters) of gas per barrel of liquid produced placed on the surface, where it is not possible to install conventional electric submersible pump systems with a single (centrifugal) gas separator, since the separation efficiency thereof is limited, especially where the operator of the field must successfully reduce the flowing bottom pressure to far below the bubble pressure of the well fluid in order to be able to ensure considerable oil production, thereby generating high gas production.

Likewise, the equipment and the method are to be used in artificial lift systems to be installed at the well bottom when the operating company needs to produce fluid in an oil well, obtaining the largest amount of gas possible on the surface for the production and sale thereof, as well as for the use thereof in order to obtain electrical energy for the self-supply of the field.

This need led to the development of an alternative that allowed a conventional electric submersible pump system with a centrifugal gas separator, which has internal rotational parts, to be installed in wells with high gas production, without the performance thereof being highly affected by the excess of said gas.

Considering the power of the centrifugal gas separators, which forms part of the pump system, and the advantages indicated in the documents mentioned, the applicant considered the need to combine these centrifugal separators with another type of separator, specifically with static separators, in the interest of optimizing the gas elimination process before sending the well fluid to the pump. The problem was how to ensure that two different types of separators, the centrifugal gas separator and the static separator, especially the anchor-type static separator, which had not been joined previously, could work together and in a coordinated manner.

DESCRIPTION OF THE FIGURES

FIG. 1 shows a centrifugal gas separator existing in the state of the art and use for electric submersible systems.

FIG. 2 shows a static gas separator, of a “gas anchor” type commonly used in mechanical pumping and PCP systems.

FIG. 3 shows an encapsulated electric submersible pump system according to the present invention.

FIG. 4 shows a diagram of the elements that comprise the separation system of the present invention, where the direction of the fluid and of the gas, once the first enters the separator, is shown.

FIG. 5 shows a diagram of performance of the first well, with the separator of the present invention installed, evaluated during the period comprised between February and April 2016.

FIG. 6 shows a diagram of performance of the first well, with the separator of the present invention installed, evaluated during the period comprised between April and July 2016.

FIG. 7 shows a diagram of performance of the second well, without the separator of the present invention, evaluated during the period comprised between April and August 2015.

FIG. 8 shows a diagram of performance of the second well, without the separator of the present invention, evaluated during the period comprised between November 2015 and January 2016.

FIG. 9 shows a diagram of performance of the second well, with the separator of the present invention installed, evaluated during the period comprised between July and December 2016.

DETAILED DESCRIPTION OF THE INVENTION

The separator of the present invention consists in the adaptation of static gas separator of a “gas anchor” type, commonly used in progressing cavity pump artificial lift systems and mechanical pumping, to an electric submersible pump system that includes a centrifugal gas separator, by means of the use of a capsule that shields one part of the electric submersible system, creating a sealed compartment from the half of the centrifugal gas separator body to the bottom sensor.

The basic construction of a centrifugal gas separator (1) used in electric submersible pump systems is shown in FIG. 1. This separator (1) is internally made up of a shaft (10) that rotates at the speed of the electric submersible motor, stabilized on the base thereof by an outer hub (101) and an inner hub (102) and on the head thereof by an outer hub (103). The well fluid enters through the intake holes (11) and is taken by the inductor (12), which begins the centrifugal movement; next, the fluid rises to the blade guide (13) and the rotor (14), where the centrifugal speed thereof increases and, due to the difference between densities, the liquid remains at the ends inside the compression tube (15) and the gas is in the center; next, the two separated fluids rise through different compartments; the gas is guided towards the vent holes (16) towards the annular space of the well and the gas-free liquid continues to rise inside the head (17) towards the pump.

Moreover, the basic construction of a “gas anchor” type gas separator (2), shown in FIG. 2, consists of a grooved hollow tube (21 a, 21 b), through which the well fluid enters, which is required to descend internally through said tube until reaching a tube with a larger inner and outer diameter (23), where the Venturi effect occurs; and during the descent thereof, the coalescence effect and the subsequent separation of free gas also occurs, due to the difference between densities, until reaching an inner hollow tube, with a smaller outer and inner diameter, referred to as immersion tube (22), through which the fluid with a smaller proportion of free gas will rise to the capsule (6). It was decided to use a tube of glue (24) with a bottom plug (25) to store solids that could be separated.

The conventional electric submersible pump system (3), shown in FIG. 3, has a bottom sensor (32) connected to a motor (31), which is protected by a lower seal (33) and an upper seal (34). A centrifugal gas separator (1), a gas handling pump (4) and a production pump (5) are coupled above the latter element. A capsule (6) that is installed from the half of the centrifugal gas separator (1), leaving the gas vent holes (16) of said separator (1) outside of it and allowing the gas to be directed towards the annular space of the well, but enclosing the intake holes (11) of the centrifugal gas separator (1) inside of it in a sealed manner, was adapted to this configuration. This capsule has an adaptor (7) with a smaller outer diameter on the lower part thereof to ensure the connection with the “gas anchor” type static gas separator (2).

The design and method for removing gas from a well fluid according to the present invention is based on two stages that are carried out by using a static gas separator and a centrifugal gas separator in an electric submersible pump system, which are coupled by means of encapsulation. This configuration is used to remove the greatest amount of free gas possible immersed in the liquid fluid of an oil well and seeks to ensure correct operation of the electric submersible pump system and performance of the well itself. Therefore, it aims to minimize the instability of the artificial lift equipment by electric submersible pumping, extending the useful life thereof and stabilizing the production of liquid fluid of an oil well.

The separator of the present invention is made up of a conventional electric submersible pump system (3) with a centrifugal gas separator (1) coupled to a static gas separator (2), commonly used in progressing cavity pump systems and mechanical pumping, by means of adapting a pipe referred to as capsule for the electric submersible pump system (ESP) (6).

The dimensions of said capsule depend on the configuration of the electric submersible pump system equipment and on the specific dimensions of the well where it is going to be installed, such as the diameter of the well hollow, deviation profile of the well, seating depth of the electric submersible equipment (3) and speed of the fluid around the motor (31) to obtain optimal cooling in this equipment.

The capsule (6) has a closed upper end, which forms a seal against the casing of the centrifugal gas separator and a lower conical end, with an adaptor (7) on the lower end, which is designed to allow for the sealed connection with the static gas separator (2) but does not come in contact with the lower end of the electric submersible equipment (3).

Specifically, the separator of the invention comprises a static separator (2) that connects to the lower end of the capsule (6), such that the upper point (22 b) of the immersion tube (22) of the static separator (2) joins to the adaptor (7).

The capsule is adapted to the height of the middle area of the centrifugal gas separator (1) of the conventional electric submersible pump system (3), enclosing the intake holes (11) of the centrifugal gas separator (1) inside of it and leaving the gas vent holes (16) of said separator (1) outside of it, which allows the gas to be directed towards the annular space of the well (8 b). This capsule (6) extends up to a length of 1 foot (30.48 cm) under the bottom sensor (32) and subsequently has a reduced diameter in the adaptor (7) with a specific angle that reduces the Venturi effect at the entry of the capsule (6).

In another alternative, the invention also relates to a method for separating gas from a well fluid which comprises the steps of:

-   -   a. Passing the fluid extracted from a well through a first “gas         anchor” type static separator (2) connected to the lower end of         a capsule (6), freeing gas bubbles into the annular space of the         well (8 a) and allowing a descending fluid stream (with a         smaller amount of free gas) to enter through the lower open         point (22 a) of the immersion tube (22) and to rise until         reaching the upper point (22 b) of said tube (22), which is         connected to the adaptor (7) of the capsule (6);     -   b. Introducing the fluid with a smaller amount of free gas into         the capsule (6), through the adaptor (7)     -   c. Passing the fluid contained in the capsule (6) through a         centrifugal gas separator (1) that is part of the conventional         electric submersible pump system (3);     -   d. Guiding the gas of the centrifugal gas separator (1) towards         the annular space of the well (8 b); and     -   e. Sending the liquid fluid with a smaller amount of gas to the         gas handling pump (24) and finally, sending it to the production         pump (25).

In a preferred embodiment of the present invention, step a) comprises the entry of the fluid with a high amount of gas into the upper and lower grooved tubes (21 a and 21 b) of the “gas anchor” type static separator (2), the descent thereof through the inner space until reaching the tubes of a larger inner and outer diameter (23 a and 23 b), where a Venturi effect occurs that reduces the speed that carries the fluid and pressure increase, and there is the phenomenon of coalescence of the gas bubbles, obtaining larger gas bubbles, which rise through the descending fluid stream, due to the difference between densities, and leave through the grooves (21 a and 21 b), through which they entered, to the annular space of the well (8 a).

Furthermore, in step c), the fluid contained in the capsule (6) enters the intake holes (11) of the centrifugal gas separator (1), which has an internal shaft that rotates at the same angular velocity as the electric submersible motor, located inside the capsule (6); the second step of gas separation occurs in this equipment (1), and in step d), the separated gas leaves through the vent holes (16) of the centrifugal gas separator (1), located outside of the capsule (6), towards the annular space of the well (8 b), rising to the surface.

EXAMPLES Field Test

The separator and the method of the invention have been successfully tested in different oil and gas producing wells in the department of Meta, Colombia; however, information from only two of these wells are provided in order to summarize and provide clarity to the behavior of the present invention.

The first is a well with hydrocarbon fluid, located in a sandstone deposit at a depth of more than 10,000 feet (3.05 km), the bubble pressure of which is around 1,800 psi. This well was drilled in 2012 and began producing oil and gas on its own, without the help of any artificial lift method, thanks to the initial pressure in its deposit and it operated as such for several months until the fraction of water increased, which caused a significant decrease in total production. Finally, in 2015, a total liquid production of less than 200 barrels (31,797.45 I) of fluid per day and a total gas production of less than 300,000 standard cubic feet (8,495,050.78 liters) of gas per day was already being reported. Given this new condition of the well, it needed an artificial lift system to extract the bottom fluids, although in technical terms it was known that once a pump is installed in the well, it would generate a significant difference in pressures between the bottom of the well and the deposit, which would cause not only an increase in the production of liquid, but also a significant increase in the production of gas. This gas would also enter the pump of the lift method installed, blocking it and causing operational problems, which would require said pump to be turned off, continuously stopping the extraction of fluids.

The operating company of the well, upon failing to find a suitable artificial lift method that increases the liquid rate without being affected by the high production of gas, decided not to intervene in the well, falling behind with few benefits due to its very low production of liquid and gas. However, this company not only had the urgent need to produce liquid fluid (water-oil), but also to increase the production of gas in order to be able to operate its gas plant in the field and thus be able to generate sufficient electrical energy that is required by its operations.

This need led to the development of an alternative that allowed a conventional electric submersible pump system with a centrifugal gas separator, which has internal rotational parts, to be installed in this well, without the performance thereof being highly affected due to the high production of gas that would be generated when it operates.

To do so, it was required to install a “gas anchor” type gas separator, commonly used in mechanical pump systems or progressing cavity pump systems, the configuration of which does not have movable but rather fixed (non-rotational) parts. This separator was installed downstream from the electric submersible pump system, with the centrifugal gas separator thereof, by means of the use of an ESP capsule, which enables both the gas anchor separator and the assembly of electric submersible pump equipment to connect, and thus obtain a primary separation of gas in the gas anchor separator that ensures that a liquid fluid enters the ESP capsule with less gas, such that the centrifugal separator can separate the remaining gas, the second stage of separation, so that an amount of gas can finally enter the pump without continuously blocking it; in other words, an amount of gas that is much less than that generated in the well, which will not cause problems to the electric submersible equipment.

The design installed in this well can be summarized in three main components: The first is the conventional electric submersible pump system (the equipment of which is coupled by flanges), which has a pump with an outer diameter of 5.38″ (13.67 cm) for handling between 300 (47,696.171) and 2200 barrels (349,771.92 I) of liquid fluid per day, with mixed flow stages and compressor configuration, which would help allow for better handling in the presence of gas in operations. A gas handling pump with a diameter of 5.13″ (13.03 cm), a Vortex-type centrifugal gas separator with a diameter of 5.38″ (13.67 cm), next two seals (motor protectors) with a diameter of 5.4″ (13.72 cm), a motor with a diameter of 5.5″ (13.97 cm) and a sensor with a diameter of 4.5″ (11.43 cm) are coupled under this system.

The second component is an ESP capsule that was constructed from a cylindrical tube with a diameter of 7″ (17.78 cm) and a length of 56 feet (17.07 m) and it hangs by means of clamps at the base of the centrifugal gas separator with a diameter of 5.38″ (13.67 cm), ensuring that the fluid entry point to the centrifugal gas separator is inside of it, although the gas vent holes of said centrifugal separator are outside of the same.

Semi-threaded plugs are installed in the upper stop of the cylinder with a diameter of 7″ (17.78 cm) and tightly seal the annular space between the body of the gas separator with a diameter of 5.38″ (13.67 cm) and the cylinder itself. These plugs were constructed in such a way they do not allow the well fluid to pass inside the capsule, but they only allow the passage of the power cable, which connects below in the head of the motor. Square threading of five threads per inch was included in the lower part of the cylinder with a diameter of 7″ (17.78 cm) in order to connect a reduction of 7″ (17.78 cm) to 3.5″ (8.89 cm) and the length of which was 1.5 feet (46 cm).

The third component is a gas anchor separator, designed by a company dedicated to the construction of gas separators for mechanical and progressing cavity pump systems, the parts of which are connected by means of threads and threaded couplings. In this case, the gas anchor type separator has two perforated tubes, each with a diameter of 3.5″ (8.89 cm) and a length of 24 feet (7.32 m), which would operate as a fluid entry point to the entire installed system. Two tubes, each with a diameter of 5.5″ (13.97 cm) and a length of 24 feet (7 m), which would allow the Venturi effect, were installed under these two tubes. Subsequently, Vortex equipment with a length of 3 feet (91.44 cm) and a diameter of 45.” (11.43 cm) was installed under these tubes in order to help separate solids in the case that they existed, and the installation of a range 2 conventional production tube with a diameter of 3.5″ (8.89 cm) and a length of 30.5 feet (9.3 m) with a plug in the bottom in order to be used as a chamber pipe for separated solids or fine elements was finally considered.

The second is a well with hydrocarbon fluid stored in a sandstone deposit at a depth of more than 8320 feet (2.54 km) and the bubble pressure of which ranges around 650 psi (4.48 MPa); however, this fluid has the particular feature of having a high density or high API gravity (approximately 8.5° API) since it is extra heavy, and therefore, the rheological properties thereof classify it as one of the most viscous crude oils in the world (viscosities around 1200 cP (1.2 Pa·s) at a temperature of 180° F. (82.22° C.), compared to less than 50 cP (0.05 Pa·s) at 180° F. (82.22° C.) of the first well). Apart from this, the fraction of water of this fluid is very low (around 10% of the total liquid). This characteristic makes separating the gas bubbles in this type of fluid much more difficult that in a fluid with very low viscosities (heavy, medium and light crudes). As a result, the centrifugal gas separation equipment of the electric submersible pump was not very efficient in the operations.

The history of this well with electric submersible pump systems of different companies shows that although the production of gas was not as high (63,900 cubic feet (1,809,445.82 I) of gas per day) in comparison to the first well (1,600,000 cubic feet (45,306,937 I) per day), the pump systems performed poorly and had unstable behavior, which prevented increasing the frequency in the pump in order to reduce the liquid column in the well to increase production. This occurred because like in the first well, by reducing the liquid column at the bottom, the pressure of the bottom is reduced, which causes greater release of gas. This gas could not be removed with the centrifugal gas separators of the conventional electric submersible pump systems, and therefore, it also required a first stage of gas separation.

The design installed in this well is summarized in three main components: The first component is the electric submersible pump system, which has two pumps with an outer diameter of 5.38″ (13.67 cm) for handling between 300 and 2200 barrels of liquid fluid per day, with mixed flow stages and compressor configuration, which would help allow for better handling in the presence of gas in operations. A gas handling pump with a diameter of 5.13″ (13.03 cm), a Vortex-type centrifugal gas separator with a diameter of 5.38″ (13.67 cm), next two seals (motor protectors) with a diameter of 5.4″ (13.72 cm), a motor with a diameter of 5.6″ (14.22 cm) and a sensor with a diameter of 4.5″ (11.43 cm) are coupled under this component.

The second component is an ESP capsule that was constructed from a cylindrical tube with a diameter of 7″ (17.78 cm) and a length of 58 feet (17.68 m) and it hangs by means of clamps at the base of the centrifugal gas separator with a diameter of 5.38″ (13.67 cm), ensuring that the fluid intake of the gas separator is inside of it, although the gas vent holes of the centrifugal gas separator are outside of the same.

Semi-threaded plugs are installed in the stop of the cylinder with a diameter of 7″ (17.78 cm) and tightly seal the annular space between the body of the gas separator with a diameter of 5.38″ (13.67 cm) and the cylinder itself. These plugs were constructed in such a way they do not allow the well fluid to pass inside the capsule, but they only allow the passage of the power cable, which connects below in the head of the motor and of a capillary tube with a diameter of ⅜″ to inject chemicals into the base of the sensor. Square threading of five threads per inch was created in the lower part of the cylinder with a diameter of 7″ (17.78 cm) in order to connect a reduction of 7″ (17.78 cm) to 3.5″ (8.89 cm) and the length of which was 1.5 feet (46 cm).

The third component is a gas anchor designed by a company dedicated to the construction of gas separators for mechanical and progressing cavity pump systems, the parts of which are connected by means of threads and threaded couplings. In this case, the gas anchor type separator has three perforated tubes, each with a diameter of 3.5″ (8.89 cm) and a length of 24 feet (7.32 m), which would operate as a fluid entry point to the entire installed system. One tube with a diameter of 5.5″ (13.97 cm) and a length of 24 feet (7.32 m), which would allow the Venturi effect, was installed under these tubes. Subsequently, under these tubes, a range 2 conventional production tube with a diameter of 3.5″ (8.89 cm) and a length of 30.5 feet (9.3 m) with a plug in the bottom in order to be used as a chamber pipe for separated solids or fine elements was installed.

Results First Well

The pump system began to operate at the end of December 2015, where the motor was well cooled since it had an operating temperature of around 275° F. (135° C.) and the bottom sensor had vibrations lower than 1G (FIGS. 5 and 6), which was quite beneficial for obtaining a good useful life of the electric submersible equipment, despite the aggressive conditions at the bottom. The intake and discharge pressures of the pump were noted with a lot of noise; however, it is worth noting that this is the result of the high gas handling of the system, and although it was not possible to separate 100% of the gas by means of the two separation stages (gas anchor separator and centrifugal gas separator), it should be noted that conventional electric submersible pump equipment could not have been able to operate under the conditions offered by the well bottom. Therefore, the test was considered to be successful. So much so that the operating company of the field emphasized this as a practical solution for its problems in wells with high gas production and it touted it as a success story in the region.

Barrels Cubic feet Barrels Barrels of fluid of gas of oil of water Gas/oil per day, per day, per day, per day, Density, ratio, Gas/liquid BFPD SCFD BOPD BWPD ° API GOR ratio, GLR Year 2015 (natural flow) DATE 200 300,000 46 154 29 6,475 1,500 Mar. 9, 2016 1,077 699,000 126 951 29 5,547 649 Apr. 29, 2016 664 1,691,000 108 556 29 15,595 2,547 May 31, 2016 1,195 1,542,000 152 1,043 29 10,161 1,290 Jul. 29, 2016 1,128 1,527,000 131 997 29 11,670 1,354 Aug. 8, 2016 860 1,545,000 115 745 29 13,407 1,797

As shown in the table of production tests of this well, in operation with the configuration (invention), in 2016 this well reported average flows of greater than 1,000 barrels (158.99 m3) of liquid per day, increasing by more than 800 barrels (127.19 m3) of liquid per day with respect to the previous condition of the well, in other words, without any artificial lift method installed at the bottom in 2015 (operated by natural flow). In addition, there was a significant increase in the gas flow, since it went from less than 300,000 cubic feet (8495.05 m3) of gas per day to reporting more than 1.5 million cubic feet (42475.25 m3) of gas per day. For the operating company, it was not only important to increase its oil production, but it was even more important to increase the production of gas, since it generates electricity with this fluid in its plants for self-supply.

Second Well

The installed pump system began operating on Jun. 26, 2016, immediately showing 7stable behavior in comparison to the previously installed electric submersible systems of other companies, even when the latter had centrifugal gas separators. As can be seen in FIGS. 7 and 8, the pressures (intake pressure), such as discharge pressure, are stable and the other variables are monitored, which ensures greater reliability of the electric submersible system and probably a longer useful life.

The greatest advantage for the operating company of this well is that with this new configuration, it has been possible to increase the speed of the pump system in order to reduce the liquid column of the well, with the aim of increasing the production thereof (by means of reducing the intake pressure of the pump), without having the increase in the gas rate cause operational problems in the pump system; in other words, the gas produced by the well is separated almost entirely by the annular space of the well and not through the pump; as a result, the system has a more stable behavior (FIG. 9). For this well, oil production has increased by 247 BOPD and a gas/liquid ratio of 307 cubic feet (8.69 m3) of gas per barrel (0.16 m3) of liquid produced is reported.

Barrels Cubic feet Barrels Barrels of fluid of gas of oil of water Gas/oil per day, per day, per day, per day, Density, ratio, Gas/liquid DATE BFPD SCFD BOPD BWPD ° API GOR ratio Apr. 2, 2016 407 63,900 366 41 8.5 174 157 Jul. 28, 2016 575 150,000 496 79 8.5 303 261 Oct. 8, 2016 711 218,000 613 98 8.5 356 307

The results obtained in both wells makes it possible to conclude that:

-   -   By applying the separator of the present invention, it is         possible to install and operate an electric submersible pump         system in oil well with very high gas production, obtaining good         operational results for the pump equipment and increases in         production for the operating company of the well.     -   The novel configuration proposed in this application enables         more gas to be removed than in a conventional electric         submersible pump system, which only comprises a centrifugal gas         separator.     -   The useful life of the electric submersible pump equipment can         benefit due to the fact that it prevents the overheating of the         pump(s) and also eliminates or at least reduces the number of         system re-starts of the system that are required because of         stoppages due to low load, caused by the blockage of the pump(s)         by gas.     -   In this way, it is also possible to decrease the losses in the         production of oil in the well due to incidents of pump blockage         by gas. 

1. A separator for removing free gas from a fluid extracted from a well comprising; a conventional electric submersible pump system; a static gas separator, the upper end of which is coupled to the lower end of a capsule, which has a closed upper end and a conical lower end with an adaptor; and a centrifugal gas separator located inside the capsule, such that the intake holes of the centrifugal gas separator are inside the capsule and the vent holes of said separator are outside the capsule.
 2. The separator for removing free gas from a fluid extracted from a well according to claim 1, characterized in that the electric submersible pump system comprises; a bottom sensor connected to a motor, which is protected by a lower seal and an upper seal, coupled in the upper part of the latter; a centrifugal gas separator; a gas handling pump; and a production pump; wherein the bottom sensor, the motor, the lower seal, and the upper seal, the centrifugal gas separator, the gas handling pump, and the produption pump are coupled by flanges.
 3. The separator for removing free gas from a fluid extracted from a well according to claim 2, characterized in that the centrifugal gas separator comprises: a shaft that rotates at the speed of the electric submersible motor, stabilized on the base thereof by an outer hub and an inner hub and on the head thereof by an outer hub; a plurality of intake holes, through which the fluid enters, whereby that is the inductor begins centrifugal movement; the fluid rises to the blade guide and the rotor, whereby the centrifugal speed thereof increases and, due to the difference between densities, the liquid remains at the ends inside the compression tube and the gas in the center; wherein the two separated fluids rise through different compartments; wherein the gas is guided towards the vent holes and from there, towards the annular space of the well while the gas-free liquid continues to rise inside a head towards the pump.
 4. The separator for removing free gas from a fluid extracted from a well according to claim 1, wherein the lower end of the centrifugal gas separator is not in contact with the adaptor of the capsule.
 5. The separator for removing free gas from a fluid extracted from a well according to claim 4, characterized in that the capsule extends up to a length of 30.48 cm (1 foot) under the bottom sensor of the electric submersible equipment.
 6. The separator for removing free gas from a fluid extracted from a well according to claim 1, characterized in that the static separator is a gas anchor type separator.
 7. The separator for removing free gas from a fluid extracted from a well according to claim 6, characterized in that the static separator comprises a grooved hollow tube, through which the well fluid enters and descends internally until reaching a tube with a larger inner and outer diameter than the grooved hollow tube; wherein a Venturi effect and coalescence effect and subsequently, the separation of free gas, occur inside said tube; wherein the fluid moves through the tube until reaching an immersion tube, having a smaller inner and outer diameter than the tube with a larger inner and outer diameter than the grooved hollow tube, through which the fluid without the gas released in the static gas separator rises to the capsule.
 8. The separator for removing free gas from a fluid extracted from a well according to claim 7, characterized in that the static separator further comprises a tube of glue with a bottom plug to store solids for segaration.
 9. The separator for removing free gas from a fluid extracted from a well according to claim 7, characterized in that an upper point of the immersion tube of the static separator joins to the adaptor.
 10. The separator for removing free gas from a fluid extracted from a well according to claim 9, characterized in that the capsule for the electric submersible pump system (ESP) is a cylindrical tube with a diameter between 6″ (15.24 cm) and 8″ (20.32 cm) and a length between 54 feet (16.46 m) and 60 feet (18.29 m), which hangs via a plurality clamps at the base of the centrifugal gas separator.
 11. The separator for removing free gas from a fluid extracted from a well according to claim 10, characterized in that the lower conical end of the capsule has a reduced diameter of between 6″ (15.24 cm) to 8″ (20.32 cm) to one of between 3″ (7.62 cm) to 5″ (12.7 cm) and the height of said end is between 1 foot (30.48 cm) and 2 feet (60.96 cm).
 12. The separator for removing free gas from a fluid extracted from a well according to claim 10, characterized in that the lower conical end of the capsule has square threading.
 13. The separator for removing free gas from a fluid extracted from a well according to claim 10, characterized in that semi-threaded plugs that seal the annular space between the body of the centrifugal separator and the cylinder itself are installed in the upper stop of the cylinder.
 14. A method for separating gas from a well fluid, the method comprising: a. Passing the fluid extracted from a well through a static separator connected to an adaptor, thereby freeing the gas bubbles into the annular space of the well and the descending fluid stream entering through the lower open point of the immersion tube and making it rise until reaching the upper point of said tube, which is connected to the adaptor of tea capsule; b. Introducing the fluid with a smaller amount of free gas, coming from the static separator into the capsule, through the adaptor; c. Passing the fluid contained in the capsule through a centrifugal gas separator that is part of a conventional electric submersible pump system; d. Removing gas from the centrifugal gas separator towards a ring of a well through the a plurality of vent holes of said separator; and e. Sending the liquid fluid with a smaller amount of gas to a gas handling pump and from the gas handling pump to a production pump.
 15. The method according to claim 14, characterized in that stage a) comprises the entry of the fluid with a high amount of gas into upper and lower grooved tubes of the static separator, the descent thereof through the inner space until reaching a pair of tubes, the inner and outer diameter of which are larger than the diameter of the upper and lower grooved tubes; a Venturi effect and a coalescence effect occur inside the pair of tubes, which create larger gas bubbles, which rise through the descending fluid stream due to the difference between densities, and leave through the the upper and lower grooved tubes, through which they entered, to the annular space of a second well.
 16. The method according to claim 14, characterized in that in stage c), the fluid contained in the capsule enters the a plurality of intake holes of the centrifugal gas separator, located inside the capsule; a second stage of gas separation occurs in the centrifugal separator, and in stage d), the separated gas leaves through the plurality of vent holes of the centrifugal gas separator, located outside of the capsule, towards the annular space of the well. 